Record production of 102,964 barrels of oil equivalent per day (Boepd), 55 percent above third quarter 2011 production and nine percent above second quarter 2012 production. September 2012 production was 105,874 Boepd;

$492.3 million of EBITDAX, 46 percent higher than the third quarter of 2011 and 17 percent above EBITDAX for the second quarter of 2012;

A $9.45 per barrel oil differential for the third quarter of 2012, with September's differential improving to $5.19 per barrel;

Capital expenditures, excluding acquisitions, of $727 million in the third quarter of 2012, bringing total non-acquisition capital expenditures for the first nine months of 2012 to $2.3 billion.

Third quarter production and EBITDAX growth was driven by continued production increases in the Bakken play and the South Central Oklahoma Oil Province (SCOOP), the oil- and condensate-rich resource play unveiled at Continental's 2012 Investors Day on October 9, 2012. Bakken production increased 81 percent compared with the third quarter of 2011, while SCOOP production was 327 percent higher than the third quarter last year.

Seventy percent of the Company's third quarter 2012 production was oil, with the balance being natural gas and natural gas liquids.

"We expect to achieve 2012 production growth guidance of 57 percent to 59 percent," said Harold Hamm, Chairman and Chief Executive Officer. "Other positive trends we expect to continue are reduced drilling and completion cycle times and low production costs.

"2013 is shaping up as another year of production growth with efficiency gains," Mr. Hamm said. "We expect 30-to-35 percent production growth next year, the first year in our new five-year plan aimed at tripling production and proved reserves."

Financial Results

Continental reported net income of $44.1 million, or $0.24 per diluted share, for the third quarter of 2012. Adjusted earnings were $0.87 per diluted share for the quarter, excluding the combined effects of an unrealized loss on derivatives, property impairment charges and relocation expenses.

After-tax adjustments that reduced net income included a net non-cash unrealized loss on derivatives of $97.1 million, property impairment charges of $16.9 million, and $1.4 million in costs related to the Company's headquarters relocation to Oklahoma City.

For the third quarter of 2011, the Company reported net income of $439.1 million, or $2.44 per diluted share. Last year's third quarter net income, on an after-tax basis, was increased by a $332.5 million net non-cash unrealized gain on mark-to-market derivative instruments and reduced by a net charge of $16.3 million for property impairments. Adjusted earnings for the third quarter of 2011 were $0.69 per diluted share, excluding the unrealized gain on derivatives and the property impairments.

Consequently, third quarter 2012 adjusted net income of $0.87 per share was 26 percent above adjusted net income for the third quarter of 2011 and a similar increase over adjusted net income for the second quarter of 2012.

For the reconciliation to U.S. GAAP earnings per share, see "Non-GAAP Financial Measures – Adjusted earnings per share" at the end of this press release.

Oil and natural gas sales were $633.3 million for the third quarter of 2012, compared with $423.9 million for the third quarter of 2011, representing a 49 percent increase.

Third quarter 2012 EBITDAX was $492.3 million, a 46 percent increase compared with the third quarter of 2011. For the Company's definition and reconciliation of EBITDAX to net income and operating cash flows, see "Non-GAAP Financial Measures – EBITDAX" at the end of this press release.

Continental reduced production expense per barrel of oil equivalent (Boe) by six percent to $5.62 for the third quarter of 2012, compared with $5.98 per Boe for the third quarter of 2011. For the first nine months of 2012, production expense per Boe declined 15 percent to $5.34 per Boe.

General and administrative expense (G&A) was $3.31 per Boe for the third quarter of 2012, compared with G&A of $2.98 per Boe for the third quarter of 2011. G&A expense for the third quarter of 2012 included non-cash equity compensation of $0.78 per Boe and relocation expenses of $0.24 per Boe. For the same quarter last year, G&A included $0.70 per Boe for non-cash equity compensation and $0.17 per Boe for relocation expenses.

Marketing and Commodity Prices

Continental reported a blended sales price of $65.62 per Boe in the third quarter of 2012, comprised of average prices of $82.87 per barrel of crude oil and $4.00 per Mcf for natural gas. The Company's third quarter 2012 average price for crude oil does not include the effect of a $1.4 million pre-tax realized loss on derivatives for the quarter. In the third quarter of 2011, it reported a blended price of $69.57 per Boe.

The Company's third quarter 2012 oil differential declined to $9.45 per barrel, a $3.18 per barrel sequential drop from the previous quarter. In the third quarter of 2011, Continental's oil differential was $5.62. The average natural gas differential to Henry Hub for the third quarter of 2012 was a premium of $1.19 per Mcf, reflecting the high liquids content of its natural gas production. This compared with a premium of $1.30 per Mcf for the third quarter of 2011.

"We've recently seen a significant improvement in Bakken oil price differentials, reflecting higher volumes being shipped by rail to the coasts and the anticipation of increased pipeline capacity," said Rick Bott, President and Chief Operating Officer. "In mid-October, Continental was railing 21,000 barrels per day of operated production to the West Coast, a similar volume by rail to the Gulf coast, and 8,000 barrels per day to the East Coast. In November, we plan to ship 65 percent of our Bakken operated oil production by rail.

"We now have excess transportation capacity in both pipe and rail, and, with additional infrastructure projects in the planning and construction stages, capacity should remain ahead of Bakken production growth," Mr. Bott said. "Our primary focus today is identifying the highest-value opportunities to market our oil to the refinery end-customer."

Operating Highlights

Three months ended September 30,

Nine months ended September 30,

2012

2011

2012

2011

Average daily production:

Crude oil (Bbl per day)

72,235

47,552

65,826

42,160

Natural gas (Mcf per day)

184,377

112,423

171,912

91,231

Crude oil equivalents (Boe per day)

102,964

66,289

94,478

57,365

Average sales prices: (1)

Crude oil ($/Bbl)

$

82.87

$

84.02

$

84.44

$

88.19

Natural gas ($/Mcf)

4.00

5.50

3.97

5.37

Crude oil equivalents ($/Boe)

65.62

69.57

66.06

73.25

Production expenses ($/Boe) (1)

5.62

5.98

5.34

6.31

General and administrative expenses ($/Boe) (1)(2)

3.31

2.98

3.35

3.32

Net income (in thousands)

44,096

439,143

518,874

541,136

Diluted net income per share

0.24

2.44

2.86

3.05

EBITDAX (in thousands)(3)

492,279

337,754

1,368,671

892,040

(1)

Average sales prices and per unit expenses have been calculated using sales volumes and exclude any effect of derivative transactions.

(2)

General and administrative expenses ($/Boe) includes non-cash equity compensation expense of $0.78 per Boe and relocation expense of $0.24 per Boe for the three months ended September 30, 2012 compared to non-cash equity compensation expense of $0.70 per Boe and relocation expense of $0.17 per Boe for the three months ended September 30, 2011. For the nine months ended September 30, 2012, general and administrative expenses includes non-cash equity compensation expense of $0.80 per Boe and relocation expense of $0.29 per Boe compared to non-cash equity compensation expense of $0.76 per Boe and relocation expense of $0.09 per Boe for the nine months ended September 30, 2011.

(3)

EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, and non-cash equity compensation expense. EBITDAX is not a measure of net income or operating cash flows as determined by U.S. GAAP. Reconciliations of net income and operating cash flows to EBITDAX are provided subsequently under the header Non-GAAP Financial Measures – EBITDAX.

The following table presents the Company's average daily production by region for the periods presented.

3Q

2Q

3Q

Boe per day

2012

2012

2011

North Region:

North Dakota Bakken

55,918

47,166

28,987

Montana Bakken

6,535

6,305

5,518

Red River Units

14,916

15,482

14,954

Other

1,343

1,445

1,052

South Region:

NW Cana Woodford

11,320

13,516

5,949

SCOOP Woodford

5,183

3,156

1,215

Arkoma Woodford

4,061

3,806

4,099

Other

2,590

2,912

3,387

East Region

1,098

1,064

1,128

Total

102,964

94,852

66,289

North Dakota and Montana Bakken Production Continues to Grow

Continental's Bakken production was 62,453 Boepd for the third quarter of 2012, an 81 percent increase over the third quarter of 2011 and 17 percent higher than the second quarter of 2012.

The Company participated in 137 gross (46 net) wells in the Bakken during the third quarter of 2012.

In terms of operated wells, Continental completed 46 gross (34 net) wells in the Bakken in the third quarter of 2012, with 41 gross (29 net) wells in North Dakota and 5 gross (5 net) wells in Montana.

Company-operated wells completed during the third quarter averaged 1,076 Boepd for North Dakota Bakken wells and 886 Boepd for Montana wells in their initial one-day test-periods. Twenty-two of Continental's 41 gross operated wells in North Dakota had initial production test rates of more than 1,000 Boepd, while two of its five operated Montana wells surpassed that level in the third quarter of 2012. Bakken well performance continues to meet the Company's expectations.

A notable project completed during the third quarter of 2012 was the Antelope-Bohmbach ECO-Pad® in McKenzie County, consisting of the Antelope 3-23H and 4-23H and the Bohmbach 3-35H and 4-35H wells. The four wells tested at an aggregate initial rate of 6,240 Boepd in total, for an average of 1,560 Boepd per well, with average flowing tubing pressure of 3,800 psi. Continental has an 85 percent working interest in the wells.

Continental is the leading leaseholder in the Bakken, with 984,040 net acres at September 30, 2012. The Company currently has 19 operated drilling rigs in the Bakken, including 15 operated rigs in North Dakota and four in Montana.

SCOOP/Northwest Cana Woodford Results (Oklahoma)

Continental's SCOOP production was 5,183 Boepd in the third quarter of 2012, a 327 percent increase over third quarter production last year and 64 percent above second quarter 2012 production. Third quarter 2012 production volumes were temporarily impacted in SCOOP as infrastructure was added to handle increasing volumes. This oil- and condensate-rich play primarily involves 197,340 net acres leased as of September 30, 2012 in Grady, McClain, Garvin, Stephens, Murray, Carter and Love counties.

In the Northwest Cana, which is comprised primarily of acreage in Blaine and Dewey counties, third quarter 2012 production was 11,320 Boepd, a 90 percent increase over production for the same period last year. Production declined from the second quarter of 2012 due to reduced drilling activity and third-party infrastructure downtime.

Continental differentiates the SCOOP area from other Oklahoma Woodford plays (NW Cana and Arkoma) because of its significant oil volumes and associated economics.

The Company participated in 12 gross (5 net) wells in SCOOP and Northwest Cana during the quarter. In terms of Continental-operated wells, it completed five gross (four net) SCOOP wells in the third quarter of 2012. The five operated wells tested at an average rate of 754 Boepd in one-day test periods, with oil production averaging 28 percent.

Continental is currently operating six drilling rigs in SCOOP and none in Northwest Cana.

Financial Position and Derivatives

At September 30, 2012, the Company's balance sheet included $259.4 million in cash and cash equivalents and $2.9 billion in total long-term debt, which included no borrowings under Continental's revolving credit facility. Continental's revolving credit facility includes $1.5 billion in bank commitments and a borrowing base of $2.75 billion.

On August 16, 2012, the Company completed the placement of $1.2 billion of new 5% senior unsecured notes due 2022 at 102.375% of par, yielding 4.624%. Continental used part of the net proceeds to pay down outstanding amounts on borrowings under its revolving credit facility.

Aside from $2.3 billion of non-acquisition capital expenditures in the first nine months of 2012, Continental reported an additional $594 million in capital expenditures acquiring producing and non-producing properties.

"Our debt-to-EBITDAX metrics remain strong, and we have ample liquidity to fund our robust production growth," said John Hart, Senior Vice President and Chief Financial Officer.

Continental has systematically established derivative positions to stabilize cash flow as it continues to grow production. Derivative positions as of October 26, 2012 are listed in the following table.

Crude Oil Derivative Positions

Swaps

Collars Wtd. Avg. Price

Period and Type of Contract

Bbls

Wtd. Avg. Price

Floor

Ceiling

October 2012 - December 2012

Swaps - WTI

1,840,000

$88.69

Swaps - Brent

1,058,000

$111.17

Collars - WTI

1,340,440

$80.00

$94.71

January 2013 - December 2013

Swaps - WTI

11,862,500

$92.66

Swaps - Brent

2,372,500

$109.19

Collars - WTI

8,760,000

$86.92

$99.46

January 2014 - December 2014

Swaps - WTI

10,311,250

$96.20

Swaps - Brent

4,745,000

$100.43

Collars - Brent

1,460,000

$90.00

$107.50

January 2015 - December 2015

Swaps - Brent

1,277,500

$98.48

Natural Gas Derivative Positions

Swaps

Period and Type of Contract

MMBtus

Wtd. Avg. Price

January 2013 - December 2013

Swaps - Henry Hub

18,250,000

$3.76

For additional information on crude oil and natural gas derivative positions, please see the Company's most recent SEC filings.

2013 Guidance

Continental announced the following operating and financial guidance for 2013:

2013 Production growth range

30% to 35%

Capital expenditures*

$3.4B

Price differentials:

WTI crude oil (per barrel of oil)

$8 to $11

Henry Hub natural gas (per Mcf)

+$1.00 to $1.50

Operating expenses:

Production expense per Boe

$5.50 to $5.90

Production tax as a percent

of oil and gas revenues**

8% to 9%

DD&A per Boe

$19 to $21

G&A expense per Boe***

$2.40 to $2.90

Non-cash equity compensation per Boe

$0.70 to $0.90

Income tax rate

38%

Deferred taxes

90% to 95%

* Excludes acquisition capital expenditures

**Does not include other expenses, such as natural gas transportation fees, which could represent another 1%.

***Excludes non-cash equity compensation

Conference Call Information

Continental Resources plans to host its third quarter 2012 earnings conference call on Thursday, November 8, 2012, at 10 a.m. ET (9 a.m. CT). Those wishing to listen to the conference call may do so via the Company's web site at www.clr.com or by phone:

Time and date:

10 a.m. ET

Thursday, November 8, 2012

Dial in:

888 680 0878

Intl. dial in:

617 213 4855

Pass code:

32316165

A replay of the call will be available for 30 days on the Company's web site or by dialing:

Replay number:

888 286 8010

Intl. replay

617 801 6888

Pass code:

72440131

Conference Presentations

Continental management is currently scheduled to present at the following research conferences. Presentation materials will be available on the Company's web site.

Continental Resources is a Top 10 petroleum liquids producer in the United States. In October 2012, the Company announced a new five-year plan to triple production and proved reserves by year-end 2017. The Company's growth plan is based on developing its industry-leading leasehold in the nation's premier oil play, the Bakken of North Dakota and Montana, as well as its position in the SCOOP and Northwest Cana plays of Oklahoma. The company reported total revenues of $1.6 billion for 2011. Visit www.clr.com for more information.

Cautionary Statement for the Purpose of the "Safe Harbor" Provisions of the Private Securities Litigation Reform Act of 1995

This press release includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements included in this press release other than statements of historical fact, including, but not limited to, statements or information concerning the Company's future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, returns, budgets, costs, business strategy, objectives, and cash flow, are forward-looking statements. When used in this press release, the words "could," "may," "believe," "anticipate," "intend," "estimate," "expect," "project," "budget," "plan," "continue," "potential," "guidance," "strategy," and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Forward-looking statements are based on the Company's current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes that the expectations reflected in the forward-looking statements are reasonable and based on reasonable assumptions, no assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate. When considering forward-looking statements, readers should keep in mind the risk factors and other cautionary statements described under Part I, Item 1A. Risk Factors included in the Company's Annual Report on Form 10-K for the year ended December 31, 2011, registration statements and other reports filed from time to time with the Securities and Exchange Commission (SEC), and other announcements the Company makes from time to time.

The Company cautions readers that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company's control, incident to the exploration for, and development, production, and sale of, crude oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating crude oil and natural gas reserves and in projecting future rates of production, cash flows and access to capital, the timing of development expenditures, and the other risks described under Part I, Item 1A. Risk Factors in the Company's Annual Report on Form 10-K for the year ended December 31, 2011, registration statements and other reports filed from time to time with the SEC, and other announcements the Company makes from time to time.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. Should one or more of the risks or uncertainties described in this press release occur, or should underlying assumptions prove incorrect, the Company's actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that the Company, or persons acting on its behalf, may make.

Except as otherwise required by applicable law, the Company disclaims any duty to update any forward-looking statements to reflect events or circumstances after the date of this press release.

General and administrative expenses ($/Boe) includes non-cash equity compensation expense of $0.78 per Boe and relocation expense of $0.24 per Boe for the three months ended September 30, 2012 compared to non-cash equity compensation expense of $0.70 per Boe and relocation expense of $0.17 per Boe for the three months ended September 30, 2011. For the nine months ended September 30, 2012, general and administrative expenses includes non-cash equity compensation expense of $0.80 per Boe and relocation expense of $0.29 per Boe compared to non-cash equity compensation expense of $0.76 per Boe and relocation expense of $0.09 per Boe for the nine months ended September 30, 2011.

Unaudited Condensed Consolidated Balance Sheets

September 30,

December 31,

2012

2011

Assets

In thousands

Current assets

$

1,194,282

$

936,373

Net property and equipment

6,922,283

4,681,733

Other noncurrent assets

109,785

27,980

Total assets

$

8,226,350

$

5,646,086

Liabilities and shareholders' equity

Current liabilities

$

1,097,484

$

1,111,801

Long-term debt

2,943,741

1,254,301

Other noncurrent liabilities

1,259,754

971,858

Total shareholders' equity

2,925,371

2,308,126

Total liabilities and shareholders' equity

$

8,226,350

$

5,646,086

Unaudited Condensed Consolidated Statements of Cash Flows

Nine months ended September 30,

2012

2011

In thousands

Net income

$

518,874

$

541,136

Adjustments to reconcile net income to net cash provided by operating activities:

Non-cash expenses

681,891

256,392

Changes in assets and liabilities

(52,868)

(127,714)

Net cash provided by operating activities

1,147,897

669,814

Net cash used in investing activities

(2,591,127)

(1,263,139)

Net cash provided by financing activities

1,649,131

627,684

Net change in cash and cash equivalents

205,901

34,359

Cash and cash equivalents at beginning of period

53,544

7,916

Cash and cash equivalents at end of period

$

259,445

$

42,275

Non-GAAP Financial Measures

EBITDAX

EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, and non-cash equity compensation expense. EBITDAX is not a measure of net income or operating cash flows as determined by U.S. GAAP. Management believes EBITDAX is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income and operating cash flows in arriving at EBITDAX because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. EBITDAX should not be considered as an alternative to, or more meaningful than, net income or operating cash flows as determined in accordance with U.S. GAAP or as an indicator of a company's operating performance or liquidity. Certain items excluded from EBITDAX are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure, as well as the historic costs of depreciable assets, none of which are components of EBITDAX. Our computations of EBITDAX may not be comparable to other similarly titled measures of other companies. We believe EBITDAX is a widely followed measure of operating performance and may also be used by investors to measure our ability to meet future debt service requirements, if any. Our credit facility requires that we maintain a total funded debt to EBITDAX ratio of no greater than 4.0 to 1.0 on a rolling four-quarter basis. This ratio represents the sum of outstanding borrowings and the letters of credit under our credit facility plus our note payable and senior note obligations, divided by total EBITDAX for the most recent four quarters. Our credit facility defines EBITDAX consistently with the definition of EBITDAX utilized and presented by us. The following table is a reconciliation of our net income to EBITDAX for the periods presented.

Three months ended September 30,

Nine months ended September 30,

2012

2011

2012

2011

in thousands

Net income

$

44,096

$

439,143

$

518,874

$

541,136

Interest expense

39,205

18,981

95,174

56,737

Provision for income taxes

22,931

270,488

315,819

333,685

Depreciation, depletion, amortization and accretion

189,374

105,085

499,847

264,236

Property impairments

27,375

26,225

93,153

66,315

Exploration expenses

4,899

9,814

17,752

21,660

Impact from derivative instruments:

Total (gain) loss on derivatives, net

158,294

(537,340)

(144,377)

(372,490)

Total realized gain (loss) (cash flow) on derivatives, net

(1,394)

1,113

(48,375)

(30,981)

Non-cash (gain) loss on derivatives, net

156,900

(536,227)

(192,752)

(403,471)

Non-cash equity compensation

7,499

4,245

20,804

11,742

EBITDAX

$

492,279

$

337,754

$

1,368,671

$

892,040

The following table provides a reconciliation of our net cash provided by operating activities to EBITDAX for the periods presented.

Nine months ended September 30,

2012

2011

in thousands

Net cash provided by operating activities

$

1,147,897

$

669,814

Current income tax provision (benefit)

(7,724)

9,331

Interest expense

95,174

56,737

Exploration expenses, excluding dry hole costs

17,433

17,902

Gain on sale of assets, net

67,139

15,387

Other, net

(4,116)

(4,845)

Changes in assets and liabilities

52,868

127,714

EBITDAX

$

1,368,671

$

892,040

Adjusted earnings per share

Our presentation of adjusted earnings per share that excludes the effect of certain items is a non-GAAP financial measure. Adjusted earnings per share represents diluted earnings per share determined under U.S. GAAP without regard to non-cash gains and losses on derivative instruments, property impairments, gains and losses on asset sales, and corporate relocation expenses. Management believes this measure provides useful information to analysts and investors for analysis of our operating results on a recurring, comparable basis from period to period. In addition, management believes this measure is used by analysts and others in valuation, comparison and investment recommendations of companies in the oil and gas industry to allow for analysis without regard to an entity's specific derivative portfolio, impairment methodologies, and nonrecurring transactions. Adjusted earnings per share should not be considered in isolation or as a substitute for earnings per share as determined in accordance with U.S. GAAP and may not be comparable to other similarly titled measures of other companies. The following table reconciles earnings and diluted earnings per share as determined under U.S. GAAP to adjusted earnings and adjusted diluted earnings per share.

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